1. Field of the Invention
The invention relates generally to the field of passive detection and imaging of subsurface occurring seismic events. More particularly, the invention relates to such techniques as may be applied in rock formations with transverse isotropy with vertical axis of symmetry (“VTI”).
2. Background Art
Passive seismic emission tomography is a process in which an array of seismic sensors is deployed in a selected pattern on or near the Earth's surface (or on the sea floor in marine surveys) and seismic energy is detected at the sensors that emanates from various seismic events occurring within the Earth's subsurface. Processing the signals detected by the sensors is used to determine, among other things, the position in the Earth's subsurface at which the various seismic events took place, the mechanism of failure of the formation and the origin time of such events.
Applications for passive seismic emission tomography include, for example, determining the point of origin of microearthquakes caused by movement along geologic faults (breaks in rock layers or formations), fracture propagation in nuclear storage sites, movement of fluid in subsurface reservoirs, wellbore mechanical processes (e.g., casing failures), and monitoring of movement of proppant-filled fluid injected into subsurface reservoirs to increase the effective wellbore radius of wellbores drilled through hydrocarbon-producing subsurface Earth formations (“fracturing”). The latter application, known as “frac monitoring” is intended to enable the wellbore operator to determine, with respect to time, the direction and velocity at which the proppant filled fluid moves through particular subsurface Earth formations.
One particularly useful technique for passive detection of origin position and time of subsurface occurring seismic events is described in U.S. Pat. No. 7,663,970 issued to Duncan et al. and assigned to the assignee of the present invention. The technique described in the foregoing patent includes transforming seismic signals recorded at selected positions into a domain of possible spatial positions of a source of seismic events. An origin in spatial position and time of at least one seismic event is determined from space and time distribution of at least one attribute of the transformed seismic data.
However, the correct characterization of microseismic events is dependent on using an accurate model of the velocities of the subsurface rock formations. Passive microseismic monitoring known in the art is carried out with temporarily deployed sensor arrays, either deployed in one or more subsurface monitoring wells or on the surface, as explained above. More recently, it is known in the art to semi-permanently or permanently deploy seismic sensors (e.g., geophones) in shallow boreholes (“buried array”) to provide consistent microseismic mapping among different fracture treatments at the scale of a subsurface reservoir. This type of monitoring allows development of a consistent velocity model used for all fracture treatments used in a particular reservoir.
A particular consideration in accurate velocity model development is that certain subsurface rock formations exhibit seismic velocity anisotropy. Seismic anisotropy is the dependence of seismic velocity upon wave propagation direction. See, Thomsen, L., 1986, Weak elastic anisotropy, Geophysics, 51(10), 1954-1966.
Seismic anisotropy has been used widely with controlled source seismic surveying to improve reservoir imaging (see, e.g., Tsvankin, I., and V. Grechka, 2006, Developments in seismic anisotropy: Treating realistic subsurface models in imaging and fracture detection: CSEG Recorder, 31 (special edition), 43-46), lithogy discrimination (e.g., shales versus sands) (see, Vernik, L., 2007, Anisotropic correction of sonic logs in wells with large relative dip, Geophysics 73, E1 (2008); doi:10.1190/1.2789776), characterizing fractures and stresses, and monitoring the time-lapse changes in seismic characteristics of subsurface formations from which fluids are withdrawn (e.g., oil and gas). In controlled source (“active”) seismic surveying, incorporating elastic anisotropy into migration algorithms allows proper positioning of reflectors, and further enhances the understanding of regional velocity structures. In passive seismic, accounting for velocity anisotropy is important among other parameters for obtaining accurate hypocenter locations, source mechanisms and optimal stacking of far offset receivers.
Current migration-type passive seismic event location techniques generally rely on compressional (“P”) wave stacking from vertically sensitive seismic sensors (e.g., geophones or accelerometers). Typically, the velocity models are derived from 1D acoustic wellbore logs, or alternatively from vertical seismic profile (“VSP”) or “checkshot” derived 1D models. Shear and compressional velocities within shales are faster in the horizontal plane than the vertical plane due to layering. As a result, it is observed that VTI-type of anisotropy increases the horizontal velocity and can explain why correct depth location of calibration shots is obtained only with the isotropic models with increased velocity. Scaling up of the isotropic velocity may provide locally similar location accuracy of perforation shots, however if a perforation shot or microseismic event occurs at a significantly different lateral position, the foregoing approximation may produce biased results as receiver statics are tuned to a chosen calibration position only. The VTI anisotropy seems to better reflect seismic velocity than scaled-up (often 1D) isotropic velocity profile, resulting in smaller residuals and more consistent receiver statics for multiple treatments. Thus using VTI anisotropy enables faster and more constant mapping of the new microseismic events at various parts of the reservoir.
What is needed is a method for mapping of subsurface seismic events that accounts for velocity anisotropy.